International Tax Review is part of the Delinian Group, Delinian Limited, 4 Bouverie Street, London, EC4Y 8AX, Registered in England & Wales, Company number 00954730
Copyright © Delinian Limited and its affiliated companies 2023

Accessibility | Terms of Use | Privacy Policy | Modern Slavery Statement

People power in O&G transfer pricing

Aengus Barry, Brendan Burgess and Roman Webber assess the mechanism to charge for IP in the upstream oil and gas industry in light of some of the recent base erosion and profit shifting (BEPS) developments.

In no other sector of the economy does engineering brilliance, politics and risk taking combine with the random geology of plate tectonics as it does in upstream oil and gas.

Value in the industry is, and always has been, created by a coming together of the entrepreneurial drive of mankind and natural endowments. This has been so from the dawn of the industry, when advancements in drilling technology combined with geological good fortune to produce the Spindletop gusher. It has continued through the age of sub-sea exploration to the current pre-salt drilling and artic exploration which is pushing back the frontiers of today's industry.

Many oil and gas multinationals will have people making key decisions on everything from where to drill to how to exploit a reservoir as well as designing cutting edge extractive technology as part of a research and development (R&D) team. It is relatively common in the industry for the costs associated with such R&D activities to be recharged across many operating entities in the group on a common basis, such as turnover, and often with no mark-up or profit element. The logic of this approach is that any intellectual property (IP) created by the engineers is owned by those same entities paying for the R&D. Often this is formalised in a cost sharing arrangement or cost contribution arrangement (CCA) whereby all group IP is effectively shared between the participants paying for the R&D.

This approach is industry standard and has manifested itself over many decades, driven by the reluctance of joint venture (JV) partners to allow a value-based charge for IP, which in turn reflects the reluctance of many national oil companies (NOCs) to see IP royalties, or value-based, charges; from their perspective access to the oil and gas technology is one of the main reasons to partner with the multinational in the first place.

While there are other variations of this model, and while the extent to which recharges are made into an incorporated or unincorporated JV can impact the ease of a charge, much of the underlying economic logic is the same. However, many of the core objectives of the OECD's BEPS project, in particular those related to Action 8, on the transfer pricing of intangibles, will put pressure on the current IP charging mechanisms in the upstream oil and gas industry. This article looks at how the OECD's direction of travel may well affect widespread practices in this industry.

Is the arrangement really a CCA?

The first question BEPS raises is whether this arrangement will be able to be characterised as cost sharing for transfer pricing purposes in the future. One of the central themes of the Action 8 paper on cost contribution arrangements, released on April 29 2015, is that to be a member of such an arrangement it is necessary for an entity to have the functional capacity to provide input to the research and development exercise. Although at present only a discussion draft, the document suggests that the OECD guidelines be amended to make clear that any participant in a cost sharing arrangement would have to have the "capability and authority to control the risks associated with the risk-bearing opportunity under the CCA". The examples at the end of the document suggest that any entity not in possession of the requisite people skills (such as R&D risk oversight) should not be characterised as a participant in the cost sharing programme. Instead, an entity simply paying for R&D would be characterised as a capital provider, would be entitled to a risk adjusted reward on their capital invested and, crucially, would be expected to pay an arm's-length fee for access to the intangibles they use.

While a detailed functional and risk analysis would be required to verify on the basis of the facts for every group, it is likely that in in the eyes of the G20/OECD, upstream asset owning companies may be users of IP, not co-generators.

If the OECD transfer pricing guidelines are revised in line with the current draft, it suggests that a transfer price specifically for intellectual property is warranted, a departure from current industry practices.

How to price the use of IP?

On June 4 2015 the OECD released a further BEPS transfer pricing paper, on to hard to value intangibles and in July a public consultation was held at OECD. The paper puts forward a number of proposals. At the outset it implies that pricing IP with respect to direct comparables (licences between, two independent third parties for similar IP) often are not reliable. It also suggests other methods such as profit split, which seek to analyse the value added by the IP in question with reference to the end profits realised from the venture, may be more appropriate.

There is a link here also to the cost contribution arrangements paper noted above which suggests that, if a CCA is in place , payments for R&D should be on the basis of value, not cost (which has hitherto normally been the case).

In some (rare) instances in the upstream oil and gas industry this could be relatively straightforward – if technology allows well production to be increased by a measurable figure (for example, 10%,), or taps an entirely new reservoir, it may be possible to measure the benefit provided, and therefore, the profits to be split. However in many instances the profits derived from incremental production will be a mix of the oil price, good fortune, and of course the baseline technology. Setting aside the occasional straightforward example, determining the value add of IP generated by a group is likely to be very much easier said than done.

In this industry, however, key to determining the profits attributable to the IP in question will be determining how to split profits between the two fundamental drivers of value touched on at the beginning of this article – the asset (such as molecules of oil or gas under the ground which are very valuable but at present inaccessible), and the people that extract the molecules in question and take them to market.

Concluding comments

Charging for R&D, IP or highly skilled services on the basis of the value provided would in some cases be a change from the current modus operandi.

A group which introduces a value based IP charge may be laying itself open to challenge. However, the current situation, if continued, could just as easily be challenged by the tax authorities in countries which are home to the key people functions noted above.

There is no guarantee that OECD transfer pricing guidelines will, ultimately, move in this direction. Whilst the move towards value-based CCAs is under consideration they are not commonly found between unrelated parties, if at all. Recent court decisions that focused on adherence to the arm's-length standard of how independent parties actually price transactions may be a factor to cause the OECD to reconsider the value-based approach; as proposed guidance that departs from third-party behaviour cannot illustrate the application of the arm's-length principle. If so, then perhaps CCAs will continue to be cost-based. If not then there is, in short, no easy answer to the new questions that the draft guidance poses.

The balance between the profits which are attributable to the scarcity value of the molecules in the ground and that which is allocated to the people who help to extract those very molecules may well change in the coming years as a result of the BEPS initiative. Precisely how that occurs will be one of the key transfer pricing challenges in the years which follow.



Aengus Barry

Director, Transfer Pricing

Deloitte LLP

2 New Street Square

London EC4A 3BZ

Tel: +44 (0)207 007

Aengus joined Deloitte's transfer pricing team 13 years ago and has spent a significant portion of his career assisting clients in the energy and resources industry. He has particular experience in complex energy and resources pricing engagements, from using risk pricing statistical techniques to support the marketing margins retained by multinational mining groups to complex diversionary LNG cargo pricing assignments.

Aengus also has experience across a broad range of transfer pricing services, from documentation and compliance reports to IP planning exercises and debt pricing engagements. He has worked on a number of APAs and also has experience with wider international tax issues through participation in several tax structuring engagements.



Brendan Burgess

Partner, Transfer Pricing

Deloitte LLP

2 Hardman Street

Manchester M60 2AT

Tel: +44 (0) 161 455

Brendan is a Deloitte partner with 15 years of experience specialising in transfer pricing and business model optimisation, working in both Australia and the UK. Brendan currently leads the northern region transfer pricing practise in the UK, based in Manchester, and has extensive experience with supply chain, intellectual property and global, regional and local transfer pricing planning and documentation.

Brendan has undertaken a large number of local, regional and global transfer pricing documentation studies and advisory projects. His experience with inbound and outbound clients in the UK, along with his extensive experience in the Australian/Asia Pacific market, provides Brendan with a global perspective of transfer pricing. He has also been involved in a number of audit defence projects and APAs involving negotiations with revenue authorities in Asia Pacific and Europe. Within a varied portfolio, Brendan works with many businesses in the oilfield services and E&P sectors.



Roman Webber

Partner, Tax

Deloitte LLP

2 New Street Square

London EC4A 3BZ

Tel: + 44 (0) 20 7007

Roman Webber is a partner and leader of Deloitte's energy & resources tax practice in the UK. He has over 22 years of UK and international tax experience, which includes being the former global and UK head of renewable energy at Deloitte.

Roman leads multiple UK and international teams in the delivery of projects, having worked with companies across the energy sector, including oil majors and independents, commodity traders, service companies and power and renewables. He spent a year on secondment at a major oil & gas company in 2005 leading the tax work on the disposal of one of the businesses in more than 40 countries and coordinated teams around the globe. Roman has advised on a wide range of transactions and advisory projects including M&A, structuring, valuations, negotiations with tax authorities, financing structures, production sharing contracts (PSAs), group reorganisations, and transfer pricing. He also represents Deloitte at the UK Oil Industry Taxation Committee (UKOITC).

more across site & bottom lb ros

More from across our site

The General Court reverses its position taken four years ago, while the UN discusses tax policy in New York.
Discussion on amount B under the first part of the OECD's two-pronged approach to international tax reform is far from over, if the latest consultation is anything go by.
Pillar two might be top of mind for many multinational companies, but the huge variations between countries’ readiness means getting ahead of the game now, argues Russell Gammon, chief solutions officer at Tax Systems.
ITR’s latest quarterly PDF is going live today, leading on the looming battle between the UN and the OECD for dominance in global tax policy.
Company tax changes are central to the German government’s plan to revive the economy, but sources say they miss the mark. Ralph Cunningham reports.
The winners of the ITR Americas Tax Awards have been announced for 2023!
There is a ‘huge demand’ for tax services in the Middle East, says new Clyde & Co partner Rachel Fox in an interview with ITR.
The ECB warns the tax could leave banks with weaker capital levels, while the UAE publishes guidance on its new corporate tax regime.
Caroline Setliffe and Ben Shem-Tov of Eversheds Sutherland give an overview of the US transfer pricing penalty regime and UK diverted profits tax considerations for multinational companies.
The result follows what EY said was one of the most successful years in the firm’s history.